The present invention relates generally to electric power transmission systems and, more particularly, to monitoring of electric power transmission systems.
In August 2003, the electric power transmission system experienced the largest blackout in North American history. One seventh of the U.S. population and one third of the Canadian population were affected by this event. A total of 508 generating units shut down. One recommendation of a U.S.-Canada Power System Outage Task Force created after the blackout was to evaluate and adopt better real-time tools for operators and reliability coordinators.
Currently, electric utilities operating the power grid take measurements of power system parameters such as voltage, current and phase angle information at various points throughout their operating territories and apply them to mathematical models of the power system, its connectivity, and its various components. Information derived from these models is then used as a means of monitoring the grid and providing information for operators and coordinators. There are a number of Energy Management Systems (EMS) provided by different vendors that are currently in use by the utilities using a variety of data collecting communication protocols for gathering the monitored electric system data. These differences create challenges to sharing this information in real-time between neighboring utilities for conventional operating coordination and security. Actual power system measurements, from a subset of all key data points in the power system, are typically captured using a Supervisory Control and Data Acquisition (SCADA) system. Each substation connected to the power grid is equipped with several potential transformers and current transformers to measure voltage, current, and electric power flow on each line and bus. The real-time voltage and current data is transmitted from each substation to a central computer through a remote terminal unit. These acquired readings from throughout the power system are then processed by a state estimator algorithm to determine a complete set of the most likely values for all key points in a model of the power system. System security applications are run on these models to assess the ability of the power system to recover form various possible disturbances. This security contingency analysis attempts to determine if the power system will return to an equilibrium state or become unstable after selected system disturbances.
One characteristic of power system modeling for conventional security analysis is that the system topology and component parameters must be correct for the results to be meaningful. Inaccuracies in conventional security analysis can occur if data sampled from the actual power system are applied to a model that fails to consider a change in system topology, e.g., an open transmission line in its connectivity topology. Furthermore, inaccuracies in the models used for various power system components, such as transmission lines and power plants, can lead to an inaccurate security analysis.